After a wellbore has been drilled, it is desired to perform tests of formations surrounding the wellbore. Logging tests may be performed, and samples of formation fluids may be collected for chemical and physical analyses. The information collected from logging tests and analyses of properties of sampled fluids may be used to plan and develop wellbores and for determining their viability and potential performance.
During a well test, many types of downhole tools such as flow control valves, packers, pressure gauges, and fluid samplers are lowered into the well on a pipe string. Once a packer has been set and a cushion fluid having an appropriate density is displaced in the well above the flow control or tester valve, the valve is opened and hydrocarbons are allowed to flow to the surface where the fluids are separated and disposed of during the test. At various times during the test, the downhole tester valve is closed and the downhole pressure is allowed to build up to its original reservoir pressure. During this time, downhole gauges record the transient pressure signal. This transient pressure data is analyzed after the well test in order to determine key reservoir parameters of importance such as permeability and skin damage. Also during the course of the well test, downhole fluid samples are often captured and brought to surface after the test is completed. These samples are usually analyzed in a laboratory to determine various fluid properties which are then used to assist with the interpretation of the aforementioned pressure data, establish flow assurance during commercial production phases, and determine refining process requirements among other things.
It is often important that these fluid samples be maintained near or above the downhole pressure that existed at the time they were captured. Otherwise, as the sample is brought to surface, its pressure would naturally decrease in proportion to the natural hydrostatic gradient of the well. During this reduction in pressure, entrained gas may be released from solution, or irreversible changes such as the precipitation of wax hydrates or asphaltenes may occur which will render the captured sample non-representative of downhole conditions. For this reason, downhole samplers often have a means to hold the captured fluid sample at an elevated pressure as it is brought to surface.
The sampler device may be lowered into a wellbore on a wireline cable or other carrier line (e.g., a slickline or tubing). Such a sampler device may be actuated electrically over the wireline cable after the sampler device reaches a certain depth. Once actuated, the sampler device is able to receive and collect downhole fluids. After sampling is completed, the sampler device can then be retrieved to the surface where the collected downhole fluids may be analyzed.
In some cases, sampler devices may be attached at the end of a non-electrical cable, such as a slickline. To actuate such sampler devices, an actuating mechanism including a timer may be used. The timer may be set at the surface to expire after a set time period to automatically actuate the sampler devices. The set time period may be greater than the expected amount of time to run the test string to the desired depth.
However, a timer-controlled actuating mechanism may not provide the desired level of controllability. In some cases, the timer may expire prematurely before the sampler device is lowered to a desired location. This may be caused by unexpected delays in assembling the tool string, including wireline and slickline, in the wellbore. If prematurely activated, the sampler devices are typically retrieved back to the surface and the tool string re-run, which may be associated with significant costs and delays in well operation.
During drill stem testing operations, for example, sampler devices have been deployed in multiple numbers assembled in a carrier which can position up to 8 or 9 sampler devices around a flow path at the same vertical position as described in U.S. Pat. No. 6,439,306. Such a sampler tool typically includes a carrier having a first sub (also referred to as a “top sub”), a second sub (also referred to as a “bottom sub”), and a housing which couples the first and second subs together. The sampler devices, including their trigger mechanisms, are attached to the first sub and enclosed within the housing. This assembly is commonly known as a SCAR (which stands for Sampler Carrier) assembly. If it is desired to capture more than one sample at the same time, the SCAR design exposes each sampler device to identical surrounding fluid conditions at the time of triggering. Otherwise, if the different sampler devices were to be distributed a vertical distance along the wellbore, then there can be no assurance that differences in pressure or temperature at the different vertical locations in the wellbore will not affect the well fluid differently causing differences in the captured fluid samples.
Sampler devices of this type have traditionally been triggered using either timer mechanisms programmed at surface before the test or by rupture discs which are burst when it is desired to capture a sample by the application of annulus pressure from a pressure source at the surface. The rupture discs when burst, allow annulus fluid to enter a chamber which contains a piston. The opposing side of the piston is traditionally exposed to a chamber at atmospheric pressure or at some intermediate pressure less than annulus pressure. The pressure differential between annulus pressure and the chamber pressure generates a force on the piston which is attached to a pull rod which then moves with the piston to open a regulating valve which begins the sampling process as described in U.S. Pat. No. 6,439,306.
When the samplers are triggered using rupture discs and a pressure source from the surface in this fashion, and also when it is desired to take samples at different times, many different trigger mechanisms with multiple rupture discs having different burst pressures are needed. Because each disc has an accuracy range associated with it, and it is further desirable to have an unused safety range of pressure between each disc to avoid inadvertently bursting the wrong disc, and because other tools in the test string also rely on this same method of actuation, it is often the case that the maximum allowable casing pressure limits the number of discs that can be deployed in the test string. To overcome this limitation, sampler devices have traditionally been triggered all at once or in a limited number of combined groups. This restriction limits the flexibility of being able to take samples at different times during a well test.
It would therefore be useful to have a method by which each sampler device can be triggered independently when desired and without resorting to supplying pressure from the surface to burst a rupture disc.
One method for actuating one or more of a set of multiple fluid samplers is discussed in US 2008/0148838. In particular, US 2008/0148838 discloses an actuating method in which a control module determines that an appropriate signal has been received by a telemetry receiver and then causes a selected one or more valves to open, thereby causing a plurality of fluid samples to be taken. The telemetry receiver may be any type of telemetry receiver, such as a receiver capable of receiving acoustic signals, pressure pulse signals, electromagnetic signals, mechanical signals or the like. However, locations at which the fluid samples are taken can be extreme high-pressure and high-temperature environments in which the temperature can reach 400° F. and the pressure can reach 20,000 pounds per square inch. In the method for actuating one or more of the set of multiple fluid samplers disclosed in US 2008/0148838 only a single telemetry receiver is disclosed. If an error or malfunction occurs with respect to the single telemetry receiver, then the samples will not be taken resulting in significant delays and increases to the cost of operations.
Thus, there is a need for an improved fluid sampling system having fluid sampling devices that can be independently triggered by an operator located at the surface for collecting one or more fluid samples without the inherent risk of only using a single telemetry receiver. It is to such an improved fluid sampling system that the present disclosure is directed.